Wireless Link To Send Data Between Coil Tubing And The Surface

ABSTRACT

A well system and method for wirelessly communicating in a wellbore. The well system may comprise a coil tubing, a transceiver, a secondary transceiver, and an information handling system, wherein the information handling system is configured to record information from the transceiver. A method for wirelessly communicating in a wellbore may comprise disposing a coil tubing into the wellbore, recording a measurement with the transceiver, communicating the measurement from the transceiver to a secondary transceiver, transmitting the measurement from the secondary transceiver to one or more additional secondary transceivers, and retrieving the measurement from the one or more additional secondary transceivers by an information handling system.

BACKGROUND

A common problem associated with stimulating a wellbore is that a coiltubing system may stimulate the wellbore but a wireline system may berequired to determine the effects of the work performed on the wellboreby the coil tubing system. Traditionally, a dedicated run from thewireline system is required to determine efficacy of stimulation,however this cost considerable time, money, and effort. For example, notonly is time, money, and effort spent to rig up the coil tubing tostimulate the well, time, money, and effort is used to rig down the coiltubing so a wireline system may be rigged up to determine the effects ofthe work on the wellbore. If the effects on the wellbore are notsatisfactory, even more time, money, and effort will be exerted to rigdown the wireline and repeat the process. Examples of common types ofoperations in which this may occur are stimulation of the wellbore,cleanup, and/or acidizing and nitrogen lift.

Additionally, downhole tools disposed at the end of a wireline mayrecord information and data that may not be accessible until thewireline is removed from the wellbore. This may lead to delay inretrieving and/or processing recorded information. After processing therecorded information the wireline may be disposed back into wellbore toretrieve more information. This may increase the time, money, and effortassociated with a wireline system. Communication with downhole toolsdisposed at the end of a coil tubing may also be hampered by a lack ofability to communicate with an operator at the surface. Downhole toolsmay perform operation based off timing mechanisms, which may rush theoperation leading to ineffective results. This may also lead toexcessive amounts of lost time, money, and effort to achieve a desiredresult within the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

These drawings illustrate certain aspects of some examples of thepresent invention, and should not be used to limit or define theinvention.

FIG. 1 is an example of a well system comprising a transceiver and asecondary transciever;

FIG. 2 is an example of a well system further comprising a downholetool; and

FIG. 3 is an example of a well system further comprising a knucklejoint, a triggering mechanism, and a sampler.

DETAILED DESCRIPTION

Disclosed are a system and method that relate to the real time wirelesscommunication between tools disposed at an end of coil tubing and thesurface. During operations with coil tubing, tools utilized with thecoil tubing record information and measurements during the operation.The recorded information and measurements may not be communicated to thesurface due to physical restrictions within a wellbore. Thus, theinformation and measurements may be retrieved when the coil tubing isremoved from the wellbore. It is often costly to remove the coil tubingand access the stored information and measurements. Additionally, if themeasurements and information indicate further work may need to beperformed additional cost may be incurred to re-insert the coil tubinginto the wellbore. This process may be repeated multiple times until asatisfactory result is recorded and reported to operators on thesurface. The disclosed apparatus and method described below seeks toprevent the removal of coil tubing until all work has beensatisfactorily completed. Real time wireless communication may beutilized to transmit information and measurements to the surface in realtime.

FIG. 1 illustrates an example well system 100 for use with asubterranean well. In the illustrated embodiment, well system 100 may beused to stimulate a formation 102 (e.g., fracking, acid matrixstimulation, etc.) through coil tubing 104. In examples, coil tubing 104may be disposed within conduits (e.g., first casing 106, second casing108, etc.) The conduits may comprise a suitable material, such as steel,chromium, or alloys. As illustrated, a wellbore 110 may extend throughformation 102 and/or a plurality of formations 102. While wellbore 110is shown extending generally vertically into formation 102, theprinciples described herein are also applicable to wellbores that extendat an angle through formation 102, such as horizontal and slantedwellbores. For example, although FIG. 1 shows a vertical or lowinclination angle well, high inclination angle or horizontal placementof the well and equipment is also possible. It should further be notedthat while FIG. 1 generally depicts a land-based operation, thoseskilled in the art will readily recognize that the principles describedherein are equally applicable to subsea operations that employ floatingor sea-based platforms and rigs, without departing from the scope of thedisclosure.

As illustrated on FIG. 1, one or more conduits, shown here as firstcasing 106 and second casing 108 may be disposed in the wellbore 110.First casing 106 may be in the form of an intermediate casing, aproduction casing, a liner, or other suitable conduit, as will beappreciated by those of ordinary skill in the art. Second casing 108 maybe in the form of a surface casing, intermediate casing, or othersuitable conduit, as will be appreciated by those of ordinary skill inthe art. While not illustrated, additional conduits may also beinstalled in the wellbore 110 as desired for a particular application.In the illustrated embodiment, first casing 106 and the second casing108 may be cemented to the walls of wellbore 110 by cement 112. Withoutlimitation, one or more centralizers 114 may be attached to either firstcasing 106 and/or the second casing 108, for example, to centralize therespective conduit in wellbore 110, as well as protect additionalequipment (e.g., electromagnetic field sensors, not illustrated).

In the illustrated embodiment, well system 100 may comprise a hoist 116and a transciever 118. Without limitation, transciever 118 may bedisposed about the end of coil tubing 104. In examples, coil tubing 104may be spooled within hoist 116. In examples, hoist 116 may be used toraise and/or lower coil tubing 104, which may comprise transciever 118,in wellbore 110. Hoist 116 may attach to transciever 118 through coiltubing 104. Coil tubing 104 may be any suitable tubing that may supporttransciever 118. Coil tubing 104 may also deliver fluids, proppants,and/or the like downhole to formation 102. As discussed below, there maybe additional tools that may be disposed on coil tubing 104.

Well system 100 may further comprise an information handling system 120.Information handling system 100 may be in signal communication with thetransceiver 118. Without limitation, signals from transceiver 118 may betransmitted through secondary transceivers 122 a-122 d which may bedisposed on first casing 106. As discussed below, transceiver 118 andsecondary transceivers 122 a-122 d may operate to pass informationand/or measurements to information handling system 120. As illustrated,information handling system 120 may be disposed at surface 124. Inexamples, information handling system 120 may be disposed downhole. Anysuitable technique may be used for transmitting signals from coil tubing104 to information handling system 120. As illustrated, a communicationlink 126 (which may be wired or wireless, for example) may be providedthat may transmit data from secondary transceivers 122 a-122 d toinformation handling system 120. Without limitation in this disclosure,information handling system 120 may include any instrumentality oraggregate of instrumentalities operable to compute, classify, process,transmit, receive, retrieve, originate, switch, store, display,manifest, detect, record, reproduce, handle, or utilize any form ofinformation, intelligence, or data for business, scientific, control, orother purposes. For example, information handling system 120 may be apersonal computer, a network storage device, or any other suitabledevice and may vary in size, shape, performance, functionality, andprice. Information handling system 120 may include random access memory(RAM), one or more processing resources (e.g. a microprocessor) such asa central processing unit 128 (CPU) or hardware or software controllogic, ROM, and/or other types of nonvolatile memory. Additionalcomponents of information handling system 120 may include one or more ofa monitor 130, an input device 132 (e.g., keyboard, mouse, etc.) as wellas computer media 134 (e.g., optical disks, magnetic disks) that maystore code representative of the above-described methods. Informationhandling system 120 may also include one or more buses (not shown)operable to transmit communications between the various hardwarecomponents. Information handling system 120 may be adapted to receivesignals from transceiver 118 that may be representative of measurementsfrom a tool disposed on coil tubing 104. Information handling system 120may act as a data acquisition system and possibly a data processingsystem that analyzes measurements, for example, to derive one or moreproperties of formation 102, measurements and/or information from tool,and/or analyzing measurements on work performed by well system 100.

As mentioned above transceiver 118 may be disposed about an end of coiltubing 104 opposite surface 124, as illustrated in FIG. 1. In examples,transceiver 118 may be disposed at any suitable location along coiltubing 104. An additional examples, there may be any number oftransceivers 118 disposed at an end of coil tubing 104 opposite surface124 which may communicate with each other before communicating withsecondary transceivers 122 a-122 d or communicate separately tosecondary transceivers 122 a-122 d. Transceiver 118 may communicate(e.g., wirelessly) with tools, not illustrated, that may be attached tocoil tubing 104 and/or wellbore 110. Furthermore, transceiver 118 maycomprise sensors that may take measurements and/or record information.Information and/or measurements recorded and/or stored on transceiver118 may be performed by an information handling system 120 disposedwithin transceiver 118, not illustrated. As transceiver 118 traversesdown wellbore 110, transceiver 118 may communicate with secondarytransceivers 122 a-122 d, which may be disposed on first casing 106and/or second casing 108. During operations, transceiver 118 maywirelessly transmit information and/or recorded measurements to asecondary transceivers 122 a-122 d which may be closest to transceiver118. As coil tubing 104 traverses wellbore 110, transceiver 118 maycommunicate with different secondary transceivers 122 a-122 d as asecond secondary transceiver 122 b comes closer to transceiver 118 thana first secondary transceiver 122 a. In examples, transceiver 118 mayhave physical contact with the tubing wall adjacent to coil tubing 104(e.g. first casing 106). This may be accomplished through one and/ormore centralizer, decentralizer, and/or relying on the inherenteccentricity of running coil tubing 106 to create an acoustic pathway.Passing information, measurements, and/or recordings to secondarytransceivers 122 a-122 d from transceiver 118, the informationmeasurements, and/or recordings may be transmitted through a chain ofsecondary transceivers 122 a-122 d to information handling system 120,which may be disposed on surface 124.

Secondary transceivers 122 a-122 d may communicate with each otherwirelessly through acoustic energy to bring information, measurements,and/or recordings to information handling system 120 disposed on surface124. Specifically, secondary transceivers 122 a-122 d may utilizeacoustic energy through a medium they may be disposed on to communicateinformation, measurements, and/or recordings from transceiver 118. Forexample, a first secondary transceiver 122 a, which may be disposed onfirst casing 106 may broadcast acoustic energy through first casing 106to second secondary transceiver 122 b which may be disposed closer tosurface 124 than first secondary transceiver 122 a. The acoustic energymay comprise information, measurements, and/or recordings fromtransceiver 118. Second secondary transceiver 122 b may capture thenacoustic energy and re-broadcast the acoustic energy to a thirdsecondary transceiver 122 c. This process may be repeated any number oftimes until the information and measurements transmitted fromtransceiver 118 may be recorded by a final secondary transceiver 122 d,which may be attached to information handling system 120 throughcommunication link 126. It should be noted that coil tubing 104 may bepulled up toward surface 124 by hoist 116 before transmittinginformation and/or measurements between transceiver 118 and secondarytransceiver 122 a-122 d. This may increase communication flow duringProduction Logging Testing (PLT) and may reduce communicationinterference. Which may be prevalent in offshore environments, whereinabrasion between coil tubing 104, tool, and first casing 106 may occurto do marine heave, which may hinder communication.

Well system 100 comprising transceiver 118 and at least one secondarytransceiver 122 a-122 d may allow an operator to wirelessly collect PLT(Production Logging Testing) data from wellbore 110 while wellbore 110may be stimulated with coil tubing 104. This may allow an operator toevaluate the success of stimulation work in well system 100 in real timewithout removing coil tubing 106 from wellbore 110, which may beexpensive and time consuming. Wireless data collection may be performednumerous times in a single operation and may be run in tandem with othersystems (not illustrated) in wellbore 110. Obtaining production dataand/or downhole samples in real-time from a flowing well while coiltubing 104 is disposed in wellbore 110 may allow for a faster, cheaper,and better understanding of formation 102. Utilizing transceiver 118 andsecondary transceivers 122 a-122 d, may allow for real time two-way datatransmission from an end of coil tubing 104 opposite surface 124. Thismay allow for two-way communication with any combination of tools suchas PLT, samplers, gauges, plugs, shut-in tools, and/or the like. Two-waycommunication may be useful during stimulation operations withinwellbore 110, for example, during a stimulation operation comprisingfracking.

FIG. 1 further illustrate well system 100 operation to introduce a fluidinto fractures 136. Well system 100 may include a fluid handling system138, which may include fluid supply 140, mixing equipment 142, andpumping equipment 144 which may be connected to coil tubing 104. Pumpingequipment 144 may be fluidly coupled with the fluid supply 140 and coiltubing 104 to communicate a fracturing fluid 146 into wellbore 110.Fluid supply 140 and pumping equipment 144 may be above surface 124while wellbore 110 is below surface 124.

Well system 100 may also be used for the injection of a pad or pre-padfluid into formation 102 at an injection rate above the fracturegradient to create at least one fracture 136 in formation 100. Wellsystem 100 may then inject fracturing fluid 146 into formation 102surrounding wellbore 110 through perforation 148. Perforations 148 mayallow communication between wellbore 110 and formation 102. Asillustrated, perforations 148 may penetrate first casing 106 and cement112 allowing communication between interior of first casing 106 andfractures 136. A plug 150, which may be any type of plug for oilfieldapplications (e.g., bridge plug), may be disposed in wellbore 110 belowperforations 148.

In accordance with systems, methods, and/or compositions of the presentdisclosure, fracturing fluid 146 may be pumped via pumping equipment 144from fluid supply 140 down the interior of first casing 106 through coiltubing 104 and into formation 102 at or above a fracture gradient offormation 102. Pumping fracturing fluid 146 at or above the fracturegradient of formation 102 may create (or enhance) at least one fracture(e.g., fractures 136) extending from the perforations 148 into formation102. During fracking operations, transceiver 118 may record informationand measurements regarding the progression of the fracking operations.Recorded information and measurements may be communicated to an operatoron the surface from transceiver 118 through secondary transceivers 122as detailed above.

FIG. 2 illustrates an example in which a downhole tool 200 may bedisposed at the end of coil tubing 104. In examples, downhole tool 200may be any type of tool that may be utilized with coil tubing 104. Forexample, tools may be utilized with coil tubing 104 to stimulatewellbore 110 prior to flowing wellbore 110 during a Drill String Test(DST). Downhole tool 200 disposed at an end of coil tubing 104 oppositesurface 124 may be beneficial if paired with transceiver 118. This mayallow for data and/or samples to be read in real-time and/or aboutreal-time from a flowing well while coil tubing 104 may be disposed inwellbore 110 during a DST. Currently, it is necessary to pull coiltubing 104 out of wellbore 110 and use a wireline to obtain this data. Atransceiver 118 communicating with secondary transceivers 122 a-122 dmay form a real-time two-way data transmission from downhole tool 200.In examples, downhole tool 200 may comprise samplers, gauges, plugs,shut-in tools, and/or the like. It should be noted that multipledownhole tools 200 may be paired with individual transceiver 118 and/ora shared transceiver 118. This may allow an operator on the surface tocontrol and/or receiver information from any number of downhole tools200. As stated above, transceiver 118 may communicate to the surfacethrough secondary transceivers 122 a-122 d.

FIG. 3 illustrate an example in which a sampler 300 may be disposed atan end of coil tubing 104 opposite surface 124. As discussed above,sampler 300 may be disposed at the end of coil tubing 104 during a DST.During a DST it may be desirable to take single-phase fluid samples.

Sampler 300 may be provided by a battery, by a mud turbine, or through awired pipe from the surface, or through some other conventional means.In a wireline or slickline environment, power may be provided by abattery or by power provided from the surface through the wired drillpipe, wireline, coil tubing, or slickline, or through some otherconventional means.

Sampler 300 may include transceiver 118, through which sampler 300communicate with other actuators and sensors disposed on coil tubing 104and/or secondary transceivers 122 a-122 d. In examples, transceiver 118may also be the port through which the various actuators (e.g. valves)and sensors (e.g., temperature and pressure sensors) in sampler 300 maybe controlled and monitored. As discussed above, transceiver 118 mayinclude information handling system 120 that may exercise control andmonitoring functions. The control and monitoring functions may beperformed by information handling system 120 in another part of coiltubing 104 (not shown) or by information handling system 102 disposed onsurface 124.

Sampler 300 may include a formation probe section, which may extractfluid from wellbore 110, as described in more detail below, and maydeliver it to a channel (not illustrated) that may extend from one endof sampler 300 to the other. The channel may be connected to otherdownhole tools. Sampler 300 may also include a quartz gauge section (notillustrated), which may include sensors to allow measurement ofproperties, such as temperature and pressure, of the fluid in thechannel. Sampler 300 may include a flow-control pump-out section (notillustrated), which may include a high-volume bidirectional pump (notillustrated) for pumping fluid through the channel. Sampler 300 mayinclude at least one sample chamber sections (not illustrated) fortesting fluid in wellbore 110.

Currently, sampling fluid may be performed by a wireline in which atriggering mechanism 304 and sampler 300 are attached to the wireline(not illustrated). In examples, information handling system 120 may senda command through secondary transceivers 122 a-122 d to transceiver 118,which may be connected to triggering mechanism 304. For example, acommand may be to activate sampler 300. Triggering mechanism may 304activate sampler 300 through a timing mechanism and/or acoustictelemetry. As disclosed, sampler 300 may attach to coil tubing 104through knuckle joint 302. Transceiver 118 may be disposed on sampler300 and/or communicate with sampler 300 from coil tubing 104. Suchcommunication may be performed wirelessly and/or through a hardconnection, such as wires. This may allow samples to be taken by sampler300 during a DST, stimulation, cleanup, and/or an acidizing and nitrogenlift. Information and/or measurements taken by sampler 300 may be storedin information handling system 120, which may be disposed downhole withtransceiver 118. In examples, transceiver may transmit the recordedinformation and/or measurements to surface 124 through secondarytransceivers 122 a-122 d, as discussed above. As discussed above, atwo-way communication may be formed utilizing a transceiver 118 andsecondary transceivers 122 a-122 d. This may allow an operator toactivate sampler 300 at any desirable location within wellbore 110.

This method and system may include any of the various features of thecompositions, methods, and system disclosed herein, including one ormore of the following statements.

Statement 1: A well system comprising a coil tubing: a transceiver,wherein the transceiver is disposed about an end of the coil tubingopposite a surface; a secondary transceiver, wherein the secondarytransceiver is disposed on a casing; and an information handling system,wherein the information handling system is configured to recordinformation from the transceiver.

Statement 2: The well system of statement 1, wherein the transceiverfurther comprise a sensor, wherein the sensor configured to takemeasurements in a wellbore.

Statement 3: The well system of statement 1 or statement 2, wherein adownhole tool is disposed at the end of the coil tubing opposite thesurface.

Statement 4: The well system of any previous statement, wherein thetransceiver is disposed on the downhole tool.

Statement 5: The well system of any previous statement, wherein thetransceiver is operable to communicate with the secondary transceiverwirelessly.

Statement 6: The well system of any previous statement, wherein thetransceiver is operable to communicate with the secondary transceiverthrough an acoustic pathway.

Statement 7: The well system of any previous statement, furthercomprising a downhole tool, wherein the downhole tool is a sampler,gauge, plug, shut-in tool, or triggering mechanism.

Statement 8: The well system of any previous statement, furthercomprising a knuckle joint, a trigger, and a sampler.

Statement 9: The well system of any previous statement, wherein thetransceiver is disposed on the trigger.

Statement 10: The well system of any previous statement, furthercomprising a plurality of transceivers disposed on the coil tubing and aplurality of secondary transceivers disposed on the casing.

Statement 11: A method for wirelessly communicating in a wellborecomprising: disposing a coil tubing into the wellbore, wherein atransceiver is disposed about an end of the coil tubing opposite asurface; recording a measurement with the transceiver, wherein thetransceiver comprises a sensor; communicating the measurement from thetransceiver to a secondary transceiver; transmitting the measurementfrom the secondary transceiver to one or more additional secondarytransceivers; and retrieving the measurement from the one or moreadditional secondary transceivers by an information handling system.

Statement 12: The method of statement 11, wherein the communicating themeasurement from the transceiver to a secondary transceiver is performedwirelessly.

Statement 13: The method of statement 11 or statement 12, wherein thecommunicating the measurement from the transceiver to a secondarytransceiver is performed through an acoustic pathway.

Statement 14: The method of statement 11-statement 13, furthercomprising pulling up the coil tubing with the hoist to transmit themeasurement.

Statement 15: The method of statement 11-statement 14, wherein atriggering mechanism and a sampler are connected to the coil tubingthrough a knuckle joint.

Statement 16: The method of statement 11-statement 15, furthercomprising transmitting a command from the information handling systemto the triggering mechanism and triggering the sampler.

Statement 17: The method of statement 11-statement 16, wherein thecommunicating the measurement is performed real time during a drillstring test.

Statement 18: The method of statement 11-statement 17, wherein thecommunicating the measurement is performed real time during a productionlogging test.

Statement 19: The method of statement 11-statement 18, furthercomprising attaching a downhole tool to the coil tubing.

Statement 20: The method of statement 11-statement 19, wherein thetransceiver is disposed on the downhole tool.

The preceding description provides various embodiments of the systemsand methods of use disclosed herein which may contain different methodsteps and alternative combinations of components. It should beunderstood that, although individual embodiments may be discussedherein, the present disclosure covers all combinations of the disclosedembodiments, including, without limitation, the different componentcombinations, method step combinations, and properties of the system. Itshould be understood that the compositions and methods are described interms of “comprising,” “containing,” or “including” various componentsor steps, the compositions and methods can also “consist essentially of”or “consist of” the various components and steps. Moreover, theindefinite articles “a” or “an,” as used in the claims, are definedherein to mean one or more than one of the element that it introduces.

For the sake of brevity, only certain ranges are explicitly disclosedherein. However, ranges from any lower limit may be combined with anyupper limit to recite a range not explicitly recited, as well as, rangesfrom any lower limit may be combined with any other lower limit torecite a range not explicitly recited, in the same way, ranges from anyupper limit may be combined with any other upper limit to recite a rangenot explicitly recited. Additionally, whenever a numerical range with alower limit and an upper limit is disclosed, any number and any includedrange falling within the range are specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues even if not explicitly recited. Thus, every point or individualvalue may serve as its own lower or upper limit combined with any otherpoint or individual value or any other lower or upper limit, to recite arange not explicitly recited.

Therefore, the present embodiments are well adapted to attain the endsand advantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, and may bemodified and practiced in different but equivalent manners apparent tothose skilled in the art having the benefit of the teachings herein.Although individual embodiments are discussed, the disclosure covers allcombinations of all of the embodiments. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. Also, the terms in the claimshave their plain, ordinary meaning unless otherwise explicitly andclearly defined by the patentee. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of those embodiments. If there is any conflict in the usages of aword or term in this specification and one or more patent(s) or otherdocuments that may be incorporated herein by reference, the definitionsthat are consistent with this specification should be adopted.

What is claimed is:
 1. A well system comprising a coil tubing: atransceiver, wherein the transceiver is disposed about an end of thecoil tubing opposite a surface; a secondary transceiver, wherein thesecondary transceiver is disposed on a casing; and an informationhandling system, wherein the information handling system is configuredto record information from the transceiver.
 2. The well system of claim1, wherein the transceiver further comprise a sensor, wherein the sensorconfigured to take measurements in a wellbore.
 3. The well system ofclaim 1, wherein a downhole tool is disposed at the end of the coiltubing opposite the surface.
 4. The well system of claim 3, wherein thetransceiver is disposed on the downhole tool.
 5. The well system ofclaim 1, wherein the transceiver is operable to communicate with thesecondary transceiver wirelessly.
 6. The well system of claim 1, whereinthe transceiver is operable to communicate with the secondarytransceiver through an acoustic pathway.
 7. The well system of claim 1,further comprising a downhole tool, wherein the downhole tool is asampler, gauge, plug, shut-in tool, or triggering mechanism.
 8. The wellsystem of claim 1, further comprising a knuckle joint, a trigger, and asampler.
 9. The well system of claim 8, wherein the transceiver isdisposed on the trigger.
 10. The well system of claim 1, furthercomprising a plurality of transceivers disposed on the coil tubing and aplurality of secondary transceivers disposed on the casing.
 11. A methodfor wirelessly communicating in a wellbore comprising: disposing a coiltubing into the wellbore, wherein a transceiver is disposed about an endof the coil tubing opposite a surface; recording a measurement with thetransceiver, wherein the transceiver comprises a sensor; communicatingthe measurement from the transceiver to a secondary transceiver;transmitting the measurement from the secondary transceiver to one ormore additional secondary transceivers; and retrieving the measurementfrom the one or more additional secondary transceivers by an informationhandling system.
 12. The method of claim 11, wherein the communicatingthe measurement from the transceiver to a secondary transceiver isperformed wirelessly.
 13. The method of claim 11, wherein thecommunicating the measurement from the transceiver to a secondarytransceiver is performed through an acoustic pathway.
 14. The method ofclaim 11, further comprising pulling up the coil tubing with the hoistto transmit the measurement.
 15. The method of claim 11, wherein atriggering mechanism and a sampler are connected to the coil tubingthrough a knuckle joint.
 16. The method of claim 15, further comprisingtransmitting a command from the information handling system to thetriggering mechanism and triggering the sampler.
 17. The method of claim11, wherein the communicating the measurement is performed real timeduring a drill string test.
 18. The method of claim 11, wherein thecommunicating the measurement is performed real time during a productionlogging test.
 19. The method of claim 11, further comprising attaching adownhole tool to the coil tubing.
 20. The method of claim 19, whereinthe transceiver is disposed on the downhole tool.